This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present techniques. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present techniques. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.
In the oil reservoir discovery and drilling industry, a critical aspect of determining where to drill wells, what type of wells to drill, managing production in existing wells, and determining the type of oil extraction methods, injection fluids, and operating conditions to utilize in a well, is in determining key physical properties of the underground area or well media. This is typically done in the industry by removing several core samples from identified underground structures or in a specific well in question and testing the core(s) or core samples for several key physical aspects. Utilizing several of these core properties, engineers and geologists can use experience, further testing, and/or models to best select where to drill wells, which type of wells to drill, what extraction methods to use in each well, extraction fluids to utilize, as well as the optimum extraction conditions to achieve maximum cost efficiency and production from a given well configuration or oil reservoir.
Three key core physical properties that may be obtained from a core sample are relative permeability, capillary pressure, and wettability. The problem in the industry is that the simple, direct, and most reliable/repeatable conventional methods in the industry require at least three separate tests to be run on a core sample to obtain each of these three core properties. Additionally making conventional techniques problematic is that these measurements cannot always be made on the same core sample and using same lab conditions (e.g., pressure, temperature and fluids). A sample used in one test to determine one of these key physical properties most often is not used in the next separate test for another of these key properties. This not only leads to additional costs and time, but may lead to correlation errors on these properties since even though the core samples may be obtained from the same general underground area or well, like fingerprints, no two core samples are exactly alike. Hence, technical issues occur such as mismatched data sets; anomalies from using different samples, test conditions, and fluids in the various tests; propagation of errors from combining results from different tests; and gaps in data sets over saturation ranges.
One of the commonly used standard tests in the industry is called a “coreflood” test. However, with conventional coreflood testing, only one of the three key properties of the core, relative permeability, is commonly measured.
Lab tests performed to obtain key rock-fluid properties often involve injecting fluids into a rock sample, also called a “core”, a “core plug” or “core sample”. One such lab technique utilized in the industry is commonly referred to as a “steady-state coreflood”. In a typical steady-state coreflood test, two different fluids are co-injected in a core plug (or core plugs stacked in series) until a steady-state condition or close to steady-state condition is obtained. The core(s) are placed between inlet and outlet end pieces during a coreflood test. The pressure in phases at the inlet and outlet of the core are often used as inputs to infer key reservoir properties, e.g., relative permeability (kr). The difference in phase pressure for the two fluids is close to zero at the outlet of the core because of the phenomenon called “Capillary End-Effect” (“CEE”); however, this difference in phase pressure is non-zero at the core inlet. In conventional coreflood testing apparatus designs, the separate phase pressures cannot be individually measured due to phase mixing at the inlet-end piece of the apparatus; hence the difference in the phase pressures at the inlet are generally assumed to be zero.
Capillary pressure (Pc) is another key rock-fluid property that is often measured in the lab. Relative permeability and capillary pressure serve as key inputs in reservoir simulation to understand flow through porous media in hydrocarbon reservoirs. Capillary pressure cannot be measured in a conventional coreflood test. Separate testing, typically with other samples than those used in the coreflood tests, must be used to measure the capillary pressure of the core sample. Common capillary pressure measurement lab techniques are centrifuge method and porous plate method, while common relative permeability measurement techniques are steady-state or unsteady state corefloods. In current practice, two separate experiments are performed on different cores to measure capillary pressure and relative permeability for a given hydrocarbon reservoir facies, which can add challenges to test interpretation. If the geological characterization of a core is erroneous, then current approach may risk misinterpretation of both these measured reservoir properties for a given reservoir facies. Additionally, often due to limitation of capillary pressure lab equipment, both capillary pressure and relative permeability measurements are often performed at different test conditions, e.g., test temperature, pore pressure, net confining stress, fluid properties, etc. However, these lab measurements could be sensitive to test conditions. It is always preferred to perform both capillary pressure and relative permeability tests at identical conditions and, if it would be possible, with the same core sample. A capillary pressure curve for a core can have both positive and negative values with fluid saturation. The positive or negative part of the capillary pressure could be called forced or spontaneous depending on the test fluids and measurement modes: imbibition or drainage. In other words, a capillary pressure curve that crosses zero pressure mark has both spontaneous and forced portions. Existing methods, like centrifuge, have limitations that they can only measure one side (either positive or negative) of a capillary pressure curve, which is also referred as forced imbibition or forced drainage part of a capillary pressure curve. It is preferred to capture full characteristic of a capillary pressure, both forced and spontaneous portions, for better depletion planning and performance prediction for a hydrocarbon reservoir.
The third key core physical property, wettability, also requires separate testing from the conventional coreflood test, as well as the separate tests described above that are required to determine the capillary pressure. Conventional testing to determine the wettability of a core sample are Amott-Harvey or USBM (U.S. Bureau of Mines) method. This method requires performing a combination of spontaneous imbibition (imbibing a core sample in a fluid) and centrifuge test for both imbibition and drainage cycles (definition discussed later)
Much of the previous work, such as Longren (see Longeron, D., Hammervold, W. L., & Skjaeveland, S. M., Jan. 1, 1995, “Water-Oil Capillary Pressure and Wettability Measurements Using Micropore Membrane Technique”, Society of Petroleum Engineers, doi:10.2118/30006-M), Richardson (see Richardson, J. G., Kerver, J. K., Hafford, J. A., & Osoba, J. S., Aug. 1, 1952, “Laboratory Determination of Relative Permeability”, Society of Petroleum Engineers, doi:10.2118/952187-G); Jennings (see Jennings, J. W., McGregor, D. S., & Morse, R. A., Jun. 1, 1988, “Simultaneous Determination of Capillary Pressure and Relative Permeability by Automatic History Matching”, Society of Petroleum Engineers. doi:10.2118/14418-PA); and Virnovsky (see Virnovsky, G. A., Guo, Y., & Skaeveland, S. M., May 15, 1995, “Relative Permeability and Capillary Pressure Concurrently Determined from Steady-State Flow Experiments”, 8th. European IOR-Symposium in Vienna, Austria) related to isolating injection phases at coreflood inlet had been performed or proposed using porous plate or membranes. In these techniques, surface chemical property (wettability preference) of porous plate or membrane only allows one phase to pass through it and repels the other phase. Drawbacks of with the use of porous plates or membranes are that it is difficult to maintain wettability for long time for certain phases, and the initial wettability can alter to different wetting condition during the course of a test. Further, many of these designs are aimed to improve the porous plate technique of capillary pressure measurement, which utilizes using a fixed wettability membrane at the outlet to only allow one phase to flow out, and are not designed for conventional coreflood tests.
Richardson (see Richardson, J. G., Kerver, J. K., Hafford, J. A., & Osoba, J. S., Aug. 1, 1952, “Laboratory Determination of Relative Permeability”, Society of Petroleum Engineers, doi:10.2118/952187-G), and Gupta (see Gupta, R., & Maloney, D. R. Nov. 10, 2014, “Intercept Method—A Novel Technique to Correct Steady-State Relative Permeability Data for Capillary End-Effects”, Society of Petroleum Engineers. doi:10.2118/171797-MS) suggested that the pressure difference between the wetting and non-wetting fluid is a measure of the capillary pressure of the sample at the inflow end. However, they did not account for the need to subtract viscous pressures contribution from inlet phase pressure difference, which this invention addresses and lays out as part of the method. They also did not provide an inlet end piece design to measure inlet phase pressure. Richardson also stated that the difference of wetting and non-wetting phase pressure at any point in porous media is equal to the capillary pressure corresponding to the saturation at the point. They demonstrated the concept by cementing wetting phase (oil) pressure probes made of ceramic porous media to core walls and gas (non-wetting) pressure probes to the rubber sleeve. Their experiments showed that the pressure difference between the wetting and non-wetting fluid inside the core is constant away from the outlet end and equals to capillary pressure. However, cementing a probe on the core is not a preferred method because it might damage the core or alter the wettability of the native-condition core. Further, cementing probes for each test could be time intensive and susceptible to leaks.
Kokkedee (see Kokkedee, J. A., Jan. 1, 1994, “Simultaneous Determination of Capillary Pressure and Relative Permeability of a Displaced Phase. Society of Petroleum Engineers”, doi:10.2118/28827-MS) and Pini (see Pini, Ronny, and Sally M Benson, 2013, “Simultaneous Determination of Capillary Pressure and Relative Permeability Curves from Core-Flooding Experiments with Various Fluid Pairs”, Water Resources Research 49 (6): 3516-30, doi: 10.1002/wrcr.20274) proposed that capillary pressure is equal to pressure drop across the core at low rates. No special end piece is utilized in this technique and this technique relies on the assumption that viscous forces are small compared to capillary forces, which is not true in many test conditions and can thus result in inaccurate results for a corefloods capillary pressure measurement.
This problem has been recognized in the industry for many years. For instance, U.S. Pat. No. 4,893,504 to O'Meara Jr. et al. (patent issued Jan. 16, 1990) attempted to devise an integrated test to solve this problem known and faced in the industry. However, O'Meara requires special and complex imaging techniques (such as X-ray CT or Nuclear Magnetic Resonance Imaging, NMRI) and employs saturation profile images of fluids in a porous sample in order to determine the relative permeability and capillary pressure of the sample. Not only do the techniques of O'Meara require expensive and require complex data collection equipment, they also require complex, and what may be somewhat subjective, analysis techniques that are not confirmed with standard industry test methods.
This problem has been recognized in the industry for many years. For instance, U.S. Pat. No. 5,493,226 to Honarpour et al. (patent issued Feb. 20, 1996) describes a method for testing a core sample to obtain at least two of these key core properties, relative permeability and capillary pressure (resistivity of the core sample, which is also measured in the Honarpour method, is an electrical property and is generally not considered as a key core property for conventional oil drilling and production). However, as can be seen, the Honarpour apparatus and test method is extremely complicated as compared to a conventional core flood test (as is described in the Description section of the present disclosure). The Honarpour method requires a very complicated apparatus, including pump controllers, multiple positive displacement cylinders placed along the length of the core sample, fluid phase-specific porous membrane, as well as a microwave generation system and detector. None of the elements are part of a conventional coreflood test apparatus.
Honarpour does however point to the problem in the art as discussed above as he notes “Further, as will be understood by those skilled in this art, relative permeability and capillary pressure are interrelated and should be measured simultaneously. However, these properties are commonly obtained from different measurements using different methods, fluids, and testing conditions on different core samples from the same reservoir. As can be imagined, this results in inconsistencies between the collected data.” (see Honarpour at column 3, lines 12-19). To our knowledge, all three (3) of these properties cannot be determined by a single coreflood test as currently utilized in the industry.
As can be seen, there is a need by practitioners of the art for a simple, accurate and effective method without the need for such apparatus as porous plates, membranes, costly x-ray or NMRI apparatus and analysis techniques (which can only provide for an “indirect measurement” of many of the coreflood properties), as well as a method with the ability to measure relative permeability, capillary pressure, and optionally, wettability utilizing a single coreflood sample. Additionally, the ability to combine relative permeability, capillary pressure and wettability tests into a single testing system and test method results in significant reduction in experimental time and effort compared to each test performed separately along with addressing the existing problems in the industry as discussed above.